This invention relates generally to creating and operating oil, gas or geothermal wells and more particularly, but not by way of limitation, to fracturing subterranean formations and determining characterizing information about the fractures, such as for use in monitoring or controlling the fracturing process or in performing subsequent fracturing jobs. This more generally includes determining characteristics of subterranean structures by obtaining and evaluating signals created in the well in response to one or more excitation events. As a specific, but non-limiting example, the present invention can be used to determine geometry (e.g., length, width and height) and events during the creation of fractures in oil or gas-bearing formations.
Characterizing a well during operations relating to creating or operating the well can provide various information about what is downhole in the well or adjacent subterranean formations. This information may be used in performing the operation(s) on the respective well, or it may be useful in planning or conducting operations on other wells. Such information includes, for example, structural information (e.g., what objects are downhole, locations of what is downhole, and events that occur downhole) and parametric information (e.g., pressure, temperature and flow rate).
For example, knowledge of fracture dimensions may permit wells to be drilled in optimal locations to take advantage of non-uniform drainage or injection patterns that hydraulic fractures may produce. In this way it may be possible to extract more of the resources in a field using a smaller number of wells than would be possible if fracture geometry were not known. Furthermore, information about the rate of hydraulic fracture growth can be used in improving the design and production of the fractures, thereby resulting in economic savings to the individuals and organizations who use hydraulic fractures in their operations.
Well characterization encompasses a wide range of technologies. One is well logging prior to installing casing. Sonar, with piezoelectric pressure signal generators operating in the audible frequency range, may be used. Sonar technology is expensive, time consuming, and relies on extensive software to interpret the reflected wave pattern.
After casing is cemented in place, well characterization typically includes techniques based on pressure/time transient analysis. In these, steady state is established, such as by making the well produce, capping it off, or by pumping fluid into the well; and then, for example, a well outlet valve at the surface is manually opened or closed at a normal speed. This starts a gradual change in well pressure, slow enough that it can be read from gauges in intervals of seconds to an hour or more. The reason for the pressure transient slowness is that the Darcy Law for fluid seepage governs it. Pressure/time data and their derivatives are graphed on semi-log and log-log coordinates. The uniqueness of these slopes provides sufficient information to estimate well productivity, formation permeability, and reservoir geometry. These tests are performed without pulsatile flow present; therefore, the data have a high signal to noise ratio.
During well servicing such as in a fracturing process, pumps requiring thousands of horsepower are in operation. Pumping rate and treating pressure are operational constraints for a number of reasons. Injecting at too high a rate and thus pressure has the potential for fracturing out of the productive zone. The rate may also be limited because some fluids degrade under high shear rate. Another reason to limit the injection pressure may be tubular structure or available pump horsepower. However, high pumping rate is desirable to achieve high fluid efficiency, defined as the ratio of fracture volume created to the fluid volume pumped.
To collect well-defined pressure/time data during pumping, one must work with strong pressure signals. At high pumping rates, velocities may reach up to 40 feet/second in the flow passages. Transient fluid flow changes make a significant impact on the local friction pressure drop. Fracturing jobs often start with a xe2x80x9cmini-fracxe2x80x9d test. To do this, the pump speed is suddenly reduced (e.g., from 15 to 10 barrels/minute). The result is a sinusoidal pressure transient from which fluid efficiency, near well damage, and minimum in situ stress can be calculated.
Fracture size is another desirable characteristic to know. This has previously been obtained using conventional hydraulic impedance testing. In conventional hydraulic impedance testing, a relatively short duration pulse is produced at the surface and then the reflected signal is observed for one peak indicating the mouth of the fracture and another, smaller peak indicating the tip of the fracture. The time between the peaks is indicative of the fracture length and with an assumed volume and fracture profile, either the height or width can be determined. A shortcoming of this technique is that it is usually done in a static fluid condition due to large amounts of noise from pumps hiding the smaller reflected peak. The time frame for the pulse is typically longer than the travel time for the wave into and out of the fracture (especially at the start of the fracture stimulation process when the fracture is relatively short), which further smears, degrades or masks the signal of interest.
Other fracturing characteristics that are desirable to know and have been determinable include breakdown pressure when the fracture begins, screenout when proppant in the fracturing fluid reaches the tip of the fracture and plugs it off, and fracture closure pressure that exists after the fracture has partially closed when the fracturing pressure is released. These have been interpolated from various pressure versus time curves. For example, screenout has been deemed to exist at the beginning of a segment having a 1:1 ratio (slope of 1) in a curve representing the square root of pressure versus the square root of time; and fracture closure pressure has been interpolated from a pressure versus square root of time plot by drawing two tangential lines to the curve and at their point of intersection taking that pressure as the fracture closure pressure.
There is the need to obtain such information as mentioned above more directly if possible rather than having to infer it as in the current state of the art.
The present invention overcomes the above-noted and other shortcomings of the prior art, and meets the aforementioned needs, by providing a novel and improved well characterizing method and system and a novel and improved fracturing method.
The present invention uses an excitation event that creates a responsive signal having lower and higher frequency components, which higher frequency component provides information about one or more characteristics of the well. For example, the present invention can be used to obtain or measure signatures of hydraulic fractures from pressure signals. In a particular application, the invention uses a dynamic pressure response during a fracture stimulation job, which response undergoes signal decomposition by the use of wavelet processing to measure the response. In one use, a pulse whose rise or fall time is shorter than the travel time in the fracture excites the fracture at its natural, or resonant, frequency. For example, a flow rate change in the form of a step function or square wave, with rise and fall times measured in milliseconds, induces the type of flow transient needed to excite a natural acoustic frequency inside the fracture. The wave reflected back through the casing perforations contains the acoustic signature of the fracture. This results in a higher frequency wave being modulated on the wellbore""s resonant lower frequency wave. The higher frequency wave provides additional information (e.g., fracture geometry, such as fracture length) about the well. Non-limiting examples of other determinable information pertaining to a subterranean fracture include: breakdown pressure at fracture initiation, the time it takes proppant to reach and to screenout the tip of the fracture, fracture growth, fracture closure pressure, relative fluid flow through respective perforations, and horsepower requirements to perform a fracture treatment. This invention allows monitoring and adjusting of the fracturing process in real time for better treatment execution.
Accordingly, the present invention provides a method of determining a characteristic of an oil, gas or geothermal well, comprising: detecting a higher frequency signal on a lower frequency signal obtained from an oil, gas or geothermal well in response to an excitation event; and using the higher frequency signal to determine a characteristic of the well.
The invention can also be broadly defined as a method of characterizing an oil, gas or geothermal well, comprising: creating in an oil, gas or geothermal well an excitation signal having a maximum amplitude change occurring within a time t1; and obtaining a frequency response from the well resulting from the excitation signal, wherein the frequency response includes a period of t2, and wherein t1 is less than t2.
Still another definition is as a method of determining a characteristic of a subterranean fracture extending from a wellbore of an oil, gas or geothermal well, comprising: detecting pressure in a fluid in the well and generating an electric signal in response; applying wavelet processing to waveforms of the electric signal to separate a higher frequency waveform from a lower frequency waveform; and determining a characteristic of the subterranean fracture from the higher frequency waveform.
Fracturing is an aspect of a particular implementation of the invention and so the invention can also be defined as a method of fracturing in a subterranean formation traversed by a wellbore, comprising: pumping fluid under pressure into an oil, gas or geothermal well to fracture a subterranean formation traversed by a wellbore of the well and to create an excitation event; detecting pressure in the fluid responsive to the excitation event and generating an electric signal in response; applying wavelet processing to waveforms of the electric signal to separate a higher frequency waveform from a lower frequency waveform; and determining a characteristic of the subterranean fracture from the higher frequency waveform. Such method may further comprise repeating the steps of pumping, detecting, applying, and determining to enlarge the fracture and to provide changes in the determined characteristic corresponding to and indicating changes in the enlarging fracture. In one implementation, determining a characteristic includes: computing a speed of sound in response to a length along the wellbore and the lower frequency waveform; and computing a length of the fracture in response to the speed of sound and the higher frequency waveform; and such method further comprises controlling the pumping of the fluid in response to the lengths computed during repeated determining steps. More generally, the definitions of the invention also can include providing control in response to the one or more determined characteristics.
The present invention also provides a method of characterizing a fracture in an oil, gas or geothermal well, comprising maintaining in a neural network computer a database of identified signature waveforms. This method further comprises inputting into the neural network computer an unidentified signature waveform from an oil, gas or geothermal well obtained using steps of: detecting pressure in a fluid in such well and generating an electric signal in response; and applying wavelet processing to waveforms of the electric signal for such other well. This method still further comprises processing the unidentified signature waveform in the neural network computer, including comparing the unidentified signature waveform to identified signature waveforms in the database, to create an identity for the unidentified signature waveform relative to an identified signature waveform in the database.
The present invention still further provides a system to determine a characteristic of an oil, gas or geothermal well, comprising: a signal sensor to sense a response in the well to an excitation event; a signal processor connected to the signal sensor, the signal processor including a computer programmed for wavelet processing such that the computer performs wavelet processing of waveforms in a response sensed by the signal sensor; and a display connected to the signal processor to output data identifying a characteristic of the well from the wavelet processed waveforms. In a particular implementation, the system further comprises an excitation signal generator to provide an excitation signal in the oil, gas or geothermal well as the excitation event.